Systems and methods for injecting fluids into a subterranean formation

ABSTRACT

There is provided apparatuses, systems, and methods for effecting injection of injection fluids into a subterranean formation, including: a bundled plurality of fluid-conducting conduits.

FIELD

The present disclosure relates to apparatuses, systems and methods for injecting fluids into a subterranean formation.

BACKGROUND

Fluids are injected into subterranean formations, such as oil reservoirs, for various treatment purposes. In some cases, fluids are injected from one or more injections wells to increase reservoir pressure so as to enhance oil recovery through a production well. Unfortunately, subterranean formations are relatively heterogeneous, and injected fluids may bypass the formation fluid and flow (or channel) to the production well without having influenced the displacement of at least a meaningful quantity of formation fluid into the production well. It is, therefore, desirable to improve the efficiency and economics of enhanced oil recovery through fluid injection.

SUMMARY

In one aspect, there is provided a system for effecting injection of injection fluids into a subterranean formation, including an apparatus disposed within a wellbore, the apparatus including bundled conduits comprising:

a plurality of fluid-conducting conduits; an outer container surrounding the conduits; and a matrix material bonded to the outer container and the conduits, such that, while the apparatus is being deployed downhole into the wellbore, the matrix material maintains, or substantially maintains, the conduits in position with respect to one another and the outer container.

BRIEF DESCRIPTION OF DRAWINGS

The preferred embodiments will now be described with the following accompanying drawings, in which:

FIG. 1 is a schematic illustration of an embodiment of a system of the present disclosure;

FIG. 2 is a schematic illustration of a waterflooding system;

FIG. 3 is a cross-sectional view of an embodiment of an apparatus of the present disclosure, disposed within an injection well;

FIG. 4 is a front perspective view of a portion of the apparatus illustrated in FIG. 3, with the carrier conduit removed for clarity;

FIG. 4A is a front perspective view of a portion of the apparatus illustrated in FIG. 3;

FIG. 5 is a flow diagram of a method of manufacturing the bundled pipe; and

FIG. 6 is a flow diagram of a method of manufacturing a bundled pipe with points of weakness.

DETAILED DESCRIPTION

As used herein, the terms “up”, “upward”, “upper”, or “uphole”, mean, relativistically, in closer proximity to the surface and further away from the bottom of the wellbore, when measured along the longitudinal axis of the wellbore. The terms “down”, “downward”, “lower”, or “downhole” mean, relativistically, further away from the surface and in closer proximity to the bottom of the wellbore, when measured along the longitudinal axis of the wellbore.

Referring to FIGS. 3 to 6, there is provided a system 100 including an apparatus 10, of any one of the embodiments described above, disposed within a wellbore 20. The apparatus 10 may be used to supply fluids into the subterranean formation, such as for purposes of producing hydrocarbons from the formation by waterflooding.

The apparatus 10 is delivered to the wellsite, either in a single piece, or in a number of sections. The apparatus 10 is deployed into the wellbore 20 with either an endless tubing (coiled tubing) unit, or service rig.

The wellbore 20 can be straight, curved, or branched. The wellbore can have various wellbore portions. A wellbore portion is an axial length of a wellbore. A wellbore portion can be characterized as “vertical” or “horizontal” even though the actual axial orientation can vary from true vertical or true horizontal, and even though the axial path can tend to “corkscrew” or otherwise vary. The term “horizontal”, when used to describe a wellbore portion, refers to a horizontal or highly deviated wellbore portion as understood in the art, such as, for example, a wellbore portion having a longitudinal axis that is between 70 and 110 degrees from vertical.

The wellbore 20 may be completed either as a cased-hole completion or an open-hole completion.

The apparatus 10 is provided for effecting injection of injection fluids into a subterranean formation 18, such as an oil reservoir. The apparatus 10 includes bundled conduits 11.

Referring to FIG. 2, in some embodiments, for example, the apparatus 10 is configured for deployment within an injection well 22, for effecting the injection of injection fluids into the subterranean formation 18 such that pressure of formation fluids within the subterranean formation is increased, thereby initiating (or inducing) production, or increasing the rate of production, of formation fluids from the subterranean formation through a production well 24. In this respect, there is also provided a production well 24 for receiving the formation fluid being flowed in response to the pressure differential between the subterranean formation 18 and the production well 24, wherein at least a fraction of the pressure differential is attributable to the injection of the injection fluid by the apparatus within the injection well 22. In some embodiments, for example, there is provided a plurality of injection wells 22, 22 a, and the wells 22, 22 a are provided to enable injection of injection fluid through these wells into the subterranean formation 18, and each one of the injection wells contributes to effecting an increase in pressure of the formation fluids within the formation well such that production is initiated or induced through the production well 24, or the rate of production of the formation fluids through the production well 24 is increased. In some embodiments, for example, when the injection fluid includes water or an aqueous solution, the process is referred to as “waterflooding”.

It is understood that the apparatus 10 could be deployed for applications relating to treatment of subterranean formations other than waterflooding.

Referring to the embodiment illustrated in FIGS. 3 and 4, in one aspect, the bundled conduits 11 include a plurality of fluid-conducting conduits 12 a, 12 b, 12 c, 12 d (four are illustrated). Each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, independently, includes a respective conduit fluid passage 14 a, 14 b, 14 c, 14 d. The apparatus also includes, respective to each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, at least one apparatus port 17. In this respect, the apparatus includes a plurality of apparatus ports 17. Each one of the at least one apparatus port 17 is provided for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation (see FIG. 1).

In another aspect, the bundled conduits 11 include a plurality of fluid-conducting conduits 12 a, 12 b, 12 c, 12 d that are constrained from moving apart from one another. In some embodiments, for example, the constraining is such that the conduits 12 a, 12 b, 12 c and 12 d are constrained from moving apart from one another while the apparatus is being deployed downhole into a wellbore 20. Each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, independently, includes a respective conduit fluid passage 14 a, 14 b, 14 c, 14 d. The apparatus also includes, respective to each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, at least one apparatus port 17. In this respect, the apparatus includes a plurality of apparatus ports 17. Each one of the at least one apparatus port 17 is provided for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation (see FIG. 1).

In some embodiments, for example, each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, independently, includes tubing. In some of these embodiments, for example, the tubing is made of any suitable material. Exemplary materials include carbon steel, stainless steel, fiberglass, plastics, or composite materials. The tubing may be constructed from individual sections or may be a single continuous piece. In some embodiments, for example, the tubing is configured to conduct high pressure fluids.

The conduits 12 a, 12 b, 12 c, 12 d may be constructed of fiber reinforced thermoplastic, for example a helically wound thermoplastic composite tape. The fibers may be any one of a variety of materials such as directional fibers and/or woven fibers, including for example carbon, aramid, fiberglass such as E-glass or S-glass, spectra, carbon, aluminum, titanium, or combinations thereof.

The bundled conduits 11 are shown in FIG. 3. The bundling or constraining is effected by a retainer 26. In this respect, the apparatus 10 further includes a retainer 26. In some embodiments, for example, the retainer 26 includes an outer container (such as in the embodiment illustrated in FIG. 3), such as an outer jacket, an outer sheath, or a carrier conduit. In this respect, where the retainer 26 includes an outer container, the conduits 12 a, 12 b, 12 c, 12 d are disposed within the container. When the conduits 12 a, 12 b, 12 c, 12 d are disposed within the container 26, an inter-tubal or inter-pipe space 141 is defined within the container 26, between the conduits 12 a, 12 b, 12 c, 12 d and the container 26. Within the inter-pipe space 141 of FIG. 3 is shown a tendon 161. If desired, the bundled conduits 11 may be constructed with any number of additional tows such as a cable, wire, or fiber optic material. A matrix material 181 fills the voids between the pipes 12 and tendon(s) and/or additional tows 171, if present. The matrix material 181 may be bonded to the container 26 and the conduits 12 a, 12 b, 12 c, 12 d such that, while the apparatus 10 is being deployed downhole into the wellbore 20, the matrix material 181 maintains, or substantially maintains, the conduits 12 a, 12 b, 12 c, 12 d in position with respect to one another and the container 26. The matrix material 181 may also be bonded to the tendon 161.

All of the conduits 12 a, 12 b, 12 c, 12 d and any associated tendon(s) 16 or tow(s) 171 may be encased in a co-extruded container 26.

The matrix material 18 may include thermoplastic material. The thermoplastic material may include resins such as, but not limited to, polyethylene, polyamide, polyethylene terephthalate, polyphenylene sulfide, polypropylene, nylon, ABS, polybutylene terephthalate, polysulfone, or polycarbonate.

The choice of resin impacts chemical resistance, vapor transmissivity, temperature resistance, toughness, UV resistance as well as other physical properties. The fiber and orientation combinations impact pressure or burst strength, modulus of elasticity and compression under load. The tape angle, number of plies or coils in the finished structure will control tensile strength or burst pressure, modulus (ductility) of the structure and wall thickness which can affect at least some of the above listed properties.

The thermoplastic matrix material may be a closed cell, pure resin, or syntactic (glass) microspheres thermoplastic and may include resins such as, but not limited to, polyamide, polyethylene terephthalate, polyphenylene sulfide, polypropylene, nylon, ABS, polybutylene terephthalate, polysulfone, or polycarbonate.

The tendon 161 may be fabricated of a second thermoplastic composite.

In the current embodiment, each one of the conduits 12 a, 12 b, 12 c, 12 d may have a relatively small diameter (in comparison to the formed bundled conduits 11) such as between about 25 mm and about 50 mm OD in the current embodiment. More specifically the OD may be between about 30 and about 40 mm OD. Each one of the conduits may have a wide range of diameters depending on the application. The conduits may be constructed of multiple wraps or multiple materials depending upon the mechanical and thermal properties needed, including mechanical strength and burst pressure. The overall diameter of the container 26 may be sized so that the internal diameter (“ID”) contacts a portion of the circumferential surface of each one of the conduits. For example the OD of the container 26 may be between about 50 mm and about 100 mm. The dimensions described in this paragraph and elsewhere in the application are but examples. The dimensions and the numbers of conduits will depend on the application.

Respective to each one of the conduits 12 a, 12 b, 12 c, 12 d, there is provided at least one first fluid conducting port 171A for conducting fluid, when fluid is flowing through the conduit fluid passage to which the first fluid conducting port is respective, externally of the respective fluid-conducting conduit. In this respect, the bundled conduits include a plurality of first fluid conducting ports 171A.

The container 26, includes, respective to each one of the conduits 12 a, 12 b, 12 c, 12 d, at least one second fluid conducting port 171B for conducting fluid, received from at least one first fluid conducting port 171A of the fluid-conducting conduit to which the second fluid conducting port (of the container 26) is respective, to a subterranean zone of the subterranean formation. In this respect, the container 26 includes a plurality of second fluid communication features 171B.

In this respect, in the embodiment illustrated in FIGS. 3, 4 and 4A, the apparatus port 17 is defined by the combination of the ports 171A and 171B.

The outer container 26 is disposed in sealing engagement, or substantially sealing engagement, with the plurality of fluid-conducting conduits 12 a, 12 b, 12 c, 12 d such that sealing, or substantial sealing, of fluid communication, within the outer container 26, between (i) the at least one first fluid conducting port 171A of one of the fluid-conducting conduits and, at least, (ii) the at least one first fluid conducting port 171A of another one of the fluid-conducting conduits, is effected.

In some embodiments, for example, the at least one port 17, respective to a one of the fluid-conducting conduits 12 a, 12 b, 12 c 12 d, is spaced apart from the at least one port 17, respective to another one of the fluid-conducting conduits 12 a, 12 b, 12 c 12 d. In some of these embodiments, for example, the spacing apart is by a minimum distance of at least 15 metres. In some embodiments, for example, the minimum distance is between 15 metres and 800 metres.

In some embodiments, for example, the at least one port 17, respective to a one of the fluid-conducting conduits 12 a, 12 b, 12 c 12 d, is spaced apart from every other port that is respective to another one of the fluid-conducting conduits 12 a, 12 b, 12 c 12 d. In some embodiments, for example, the spacing apart is by a minimum distance of at least 15 metres. In some embodiments, for example, the minimum distance is between 15 metres and 800 metres.

In some embodiments, for example, when the apparatus 10 is deployed within a wellbore, a portion of the subterranean formation 18, disposed opposite to a port 17 respective to one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, is spaced apart from a portion of the subterranean formation 18 disposed opposite to a port 17 that is respective another one of the fluid-conducting conduits 12 a, 12 b, 12 c 12 d. In some embodiments, for example, the spacing apart is by a minimum distance of at least 15 metres. In some embodiments, for example, the minimum distance is between 15 metres and 800 metres.

In some embodiments, for example, when the apparatus 10 is deployed within a wellbore, a portion of the subterranean formation 18, disposed opposite to a port 17 respective to a one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, is spaced apart from every one of the other portions of the subterranean zone 18 that is disposed opposite to a port 17 respective to another one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d. In some embodiments, for example, the spacing apart is by a minimum distance of at least 15 metres. In some embodiments, for example, the minimum distance is between 15 metres and 800 metres.

Referring to FIGS. 3 and 4, in some embodiments, for example, respective to each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, a pair of sealing members (such as any pair of successive ones of sealing members 28 a, 28 b, and 28 c) extends from the respective conduit and straddles the at least one port 17 (in the case of the embodiment illustrated in the FIGS. 3 and 4, the port 17 is defined by a combination of ports 171A and 171B). The pair of sealing members are disposed, or deployable into a disposition, to prevent, or substantially prevent, fluid communication, through a wellbore annulus 30, between: (i) the at least one port 17, disposed between the pair of sealing members, and (ii) a port 17 respective to another one of the fluid-conducting conduits. In some embodiments, for example, each one of the sealing members includes a packer.

In some embodiments, for example, when the pair of sealing members is disposed in sealing engagement with the formation 18, and while injection fluid is being injected from the at least one port 17, the pair of sealing members effects isolation, or substantial isolation, of the injected injection fluid from the remainder of the subterranean formation 18.

In some embodiments, for example, the pair of sealing members are disposed in, or deployable into a disposition of, sealing engagement, or substantially sealing engagement, with a surface that, in co-operation with at least the apparatus 10, defines the wellbore annulus 30. In some embodiments, for example, the surface is a portion of the subterranean formation 18 (such as in the case of an open hole completion). In some embodiments, for example, the surface is that of a portion of a casing that is lining the wellbore 20, or a portion of a liner that is hanging from the casing (such as in the case of a cased hole completion).

In some embodiments, for example, each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, independently, includes a valve member 42 a 42 b, 42 c, 42 d configured for at least interfering with fluid communication, through the fluid passage 14, between a fluid source upstream of the valve member 42 a 42 b, 42 c, 42 d and the at least one port 17. In some embodiments, for example, the valve member 42 a 42 b, 42 c, 42 d is configured for disposition between an open condition and a closed condition. In the open condition, fluid communication, through the fluid passage 14, is being effected between a fluid source upstream of the valve member 42 a 42 b, 42 c, 42 d and the at least one port 17. In the closed condition, sealing, or substantial sealing of fluid communication, through the fluid passage, between a fluid source upstream of the valve member 42 a 42 b, 42 c, 42 d and the at least one port 17, is being effected.

The valve member 42 a 42 b, 42 c, 42 d may be configured for manual actuation, in response to detecting water production from a producing well 24, while monitoring water production from the producing well. If water production is observed, the valve member, disposed in the conduit which is conducting the injected water, may be closed to seal, or substantially seal, fluid communication between a fluid source upstream of the valve member and the at least one apparatus port 17, and thereby mitigate unnecessary water usage.

In some embodiments, for example, the valve member 42 a 42 b, 42 c, 42 d is disposed above the wellhead 38.

In some embodiments, for example, the valve member 42 a 42 b, 42 c, 42 d is disposed above the surface 40.

Once formed, lengths of between about 2,000 and about 20,000 feet of the conduits 12 a, 12 b, 12 c, and 12 d may be coiled or spooled on reels. At any point between the formation process and spooling process, the conduits 12 a, 12 b, 12 c, and 12 d may be dimpled or otherwise provided with spaced apart points of weakened strength (i.e. frangible portions) in the circumferential wall. These frangible portions may provide points at which the conduits 12 a, 12 b, 12 c, and 12 d may be perforated, along with the sheath or jacket 26 to provide a port for the outflow of fluid as described herein above.

FIGS. 5 and 6 are flow charts of example processes 300, 400 for manufacturing the bundled conduits 11. One or more specifications for the conduits 12 a, 12 b, 12 c, and 12 d may be selected (step 402). The conduits 12 a, 12 b, 12 c, and 12 d are provided according to desired specifications (steps 304, 404) which include, for example, a stiffness or mechanical strength. The stiffness or mechanical strength is selected to enable the bundled conduits 11 to be pushed into vertical and horizontal well bore sections without collapsing under compression forces while still retaining sufficient burst pressure to be able to flood a subsurface such as a shale, sandstone, or carbonate formation.

The manufacturing methods 300, 400 may further include providing a tensile member (steps 308, 408) and a matrix material (steps 310, 410) having the same, similar or compatible polymer chemistry as the conduits 12 a, 12 b, 12 c, and 12 d. The leading ends of the conduits 12 a, 12 b, 12 c, and 12 d may be placed at the entry of an extrusion die. As disclosed, the bundled condutis 11 includes four conduits 12 a, 12 b, 12 c, and 12 d; however, any number of pipes can be included depending on the application and a desired configuration. The conduits 12 a, 12 b, 12 c, and 12 d may be placed as desired in multiple locations of the die. Further, if desired, one or more tendons 161 constructed from the same thermoplastic composite as the conduits 12 a, 12 b, 12 c, and 12 d may be located at an entry to the extrusion die. The separate and individual conduits 12 a, 12 b, 12 c, and 12 d and tendon 161 may be positioned to maintain their relative positions and alignment with respect to one another with the extrusion die and within the final bundled conduits 11. The maintaining of position of the individual conduits 12 a, 12 b, 12 c, and 12 d within the container 26 relative to one another may be helpful for maintaining alignment of the points of weakness in the internal conduits 12 a, 12 b, 12 c, and 12 d and the sheath or jacket 26 and may ease the task of identifying the location of a particular individual conduit 12 a, 12 b, 12 c, and 12 d when creating the point of weakness.

The fill or matrix material polymer resin 181 that is preferably of the same chemistry as the tendon(s) 161 and conduits 12 a, 12 b, 12 c, and 12 d may be extruded into the cavities around and throughout the one or conduits 12 a, 12 b, 12 c, and 12 d and tendon(s) 161. The fill material 181 may be a pure thermoplastic polymer or may contain additives such as glass microspheres that would that assist the overall structure to be light in weight while maintaining a homogenous nature with the other components, thereby maintaining the pressure requirements of the bundled conduits 11. The polymer resin preferably is melted during the extrusion process so that subsequent freezing integrally binds the conduits 12 a, 12 b, 12 c, and 12 d and tendons 161.

During the co-extrusion (steps 312, 412) of the conduits 12 a, 12 b, 12 c, and 12 d with the tendon(s) 161 and matrix material 181 there may be a sheath or jacket 26 extruded as well such that the sheath or jacket 26, tendon 161 and matrix 181 are contained within the sheath or jacket 26. It may be desired to cool the individual conduits 12 a, 12 b, 12 c, and 12 d to prevent melting or collapse of the conduits 12 a, 12 b, 12 c, and 12 d under the pressure and temperature of extrusion. This cooling may be accomplished by supplying a flow of air or liquid through the conduits 12 a, 12 b, 12 c, and 12 d during the co-extrusion process. When the tendon 161 is constructed from the same polymer matrix as the other components, all of the components intimately bond, creating the mechanical strength required to push the bundled conduits 11 into and within the well bore 20.

The conduits 12 a, 12 b, 12 c, and 12 d, tendons 161 and matrix material 181 may be further extruded with a sheath or jacket 26. The sheath or jacket 26 may further control the dimensions, lubricity and permeation of the final bundled conduits 11. The sheath or jacket 26 may be constructed of the same or similar polymer as the conduits 12 a, 12 b, 12 c, and 12 d, tendon 161 and matrix material 181. The sheath or jacket 26 may be coated over the conduits 12 a, 12 b, 12 c, and 12 d in a manner allowing for the location of the individual conduits 12 a, 12 b, 12 c, and 12 d to be determined externally on the sheath or jacket 26 of the bundled conduits 11. This identification of the location of the individual conduits 12 a, 12 b, 12 c, and 12 d from a perspective outside the bundled pipes 11 may be accomplished by providing a color, imprint or groove in the bundled pipes 11 on the sheath or jacket 26. The sheath or jacket 26 may also have thermoplastic composite reinforcement in similar fashion to individual conduits 12 a, 12 b, 12 c, and 12 d.

After the final bundled conduits 11 is adequately cooled (steps 314, 414), it may be spooled, coiled or reeled (step 416) for shipment. If two or more reels are needed, a mechanical connection may be required to join the different reeled lengths of bundled conduits 12. Preferably, the mechanical connection between internal conduits 12 a, 12 b, 12 c, and 12 d is to be stronger than the burst pressure of the conduits 12 a, 12 b, 12 c, and 12 d. A composite overwrap may be provided to cover any joints between the conduits 12 a, 12 b, 12 c, and 12 d and mechanical connectors (not shown) to aid in the maintenance of position of the connectors.

If desired, the bundled conduits 11 may further include a length of wire, cable or other material such as a fiber optic material towed through extrusion die during the manufacture of the bundled conduits 11. The wire, cable or fiber optic strand 171 may be used to facilitate surveillance or monitoring of conditions such as temperature and pressure within or surrounding the bundled conduits 11.

The sealing members 28 a, 28 b, 28 c may be installed at the time of deployment and are removed when retrieving the apparatus from the wellbore 20.

Operation of an embodiment of the system 100, described above, will now be described. The system includes an injection well 22 and a production well 24, with an embodiment of the apparatus 10, described above, being disposed within the injection well 22. The apparatus is deployed within the injection well 22. Each one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, of the deployed apparatus 10, includes at least one apparatus port, and either the conduits included such apparatus ports 17 prior to deployment downhole, or such apparatus ports 17 became defined within the conduits upon fracturing of the corresponding frangible portions.

Injection fluid is supplied to the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d of the apparatus 10 from a fluid source. The received injection fluid is injected through the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d into the subterranean formation 18. The injected fluid effects an increase to the pressure of the formation fluid within the subterranean formation 18. As a result, formation fluid may be produced from the production well 24. Alternatively, the rate of production of the formation fluid, through the production well 24, is increased.

In this respect, a method of supplying fluid into a subterranean formation 18 includes: deploying the apparatus including the bundled plurality of fluid-conducting conduits 12 a, 12 b, 12 c, 12 d into a wellbore 20, and supplying fluid, from a fluid supply source disposed above the surface 40, through the fluid-conducting conduits and into the subterranean formation 18.

In some embodiments, for example, the supplying includes: supplying a first zone 18A of the subterranean formation through a port 17 of a first one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, and supplying a second zone 18B of the subterranean formation through a port 17 of a second one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d. The port of the first one of the fluid-conducting conduits is spaced-apart from the port of the second one of the fluid-conducting conduits by a distance of at least 15 metres.

In some embodiments, for example, sealing, or substantial sealing, of fluid communication, through the wellbore, between the port 17 of the first one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d and the port 17 of the second one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, is effected.

In some embodiments, for example, the method further includes controlling the flow of fluid through the first one of the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d with a first valve (e.g. valve member 42 a), and controlling the flow of fluid through the second one of the fluid-conducting conduits with a second valve (e.g. valve member 42 b) that is different that the first valve (e.g. valve member 42 a). Both of the first and second valves are disposed above the surface 40.

In some embodiments, for example, the method further includes injecting of injection fluids, through the fluid-conducting conduits 12 a, 12 b, 12 c, 12 d, into the subterranean formation, such that pressure of formation fluids within the subterranean formation is increased, thereby inducing production, or increasing the rate of production, of formation fluids from the subterranean formation through a production well 24.

During operation, the production well 24 is monitored for water production. When water production from the production well 24 is detected, the valve member (e.g. valve member 42 a), disposed in the conduit which is conducting the injected water, may be manually closed to seal, or substantially seal, fluid communication between a fluid source upstream of the valve member (e.g. valve member 42 a) and the at least one apparatus port 17, thereby terminating, or at least suspending, injection of the injection fluid, and thereby mitigate unnecessary water usage. In combination, a valve member (e.g. valve member 42 b), disposed in another conduit, may be opened to thereby stimulate production from another zone within the subterranean formation.

In the above description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the present disclosure. Although certain dimensions and materials are described for implementing the disclosed example embodiments, other suitable dimensions and/or materials may be used within the scope of this disclosure. All such modifications and variations, including all suitable current and future changes in technology, are believed to be within the sphere and scope of the present disclosure. All references mentioned are hereby incorporated by reference in their entirety. 

1. A system for effecting injection of injection fluids into a subterranean formation, including an apparatus disposed within a wellbore, the apparatus including bundled conduits comprising: a plurality of fluid-conducting conduits; an outer container surrounding the conduits; and a matrix material bonded to the outer container and the conduits, such that, while the apparatus is being deployed downhole into the wellbore, the matrix material maintains, or substantially maintains, the conduits in position with respect to one another and the outer container.
 2. The system as claimed in claim 1; wherein the conduits are fabricated of a thermocomposite; and wherein the outer container is fabricated of a first thermoplastic; and wherein the matrix material is fabricated of a second thermoplastic.
 3. The system as claimed in claim 1; wherein the conduits define an inter-pipe space; and the bundled conduits further comprises a tendon fabricated of a second thermoplastic composite, the tendon located within the inter-pipe space and bonded to the matrix material.
 4. The system as claimed in claim 1 further comprising a tow line within the matrix material.
 5. The system as claimed in claim 4 wherein the tow line comprises at least one of a wire, a cable, and a fiber optic material.
 6. The system as claimed in claim 1 wherein each of the conduits further comprises spaced apart points of pipe weakness adapted to rupture at a preselected pipe pressure.
 7. The system as claimed in claim 6, wherein the outer includes a point jacket weakness corresponding to each point of conduit weakness.
 8. The system as claimed in claim 1 wherein the matrix material comprises a closed cell foamed thermoplastic.
 9. The system as claimed in claim 1, wherein each one of the conduits, independently, has a burst pressure higher than 200 psi.
 10. The system as claimed in claim 1, wherein each one of the fluid-conducting conduits includes tubing.
 11. The system as claimed in claim 1; wherein each one of the fluid-conducting conduits, independently, including a respective conduit fluid passage and a respective at least one first fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the first fluid conducting port is respective, externally of the respective fluid-conducting conduit, such that a plurality of first fluid conducting ports is provided; and wherein, respective to each one of the fluid-conducting conduits, the outer container includes at least one second fluid conducting port for conducting fluid, received from at least one first fluid conducting port of the fluid-conducting conduit to which the second fluid conducting port, of the outer container, is respective, to a subterranean zone of the subterranean formation; such that a plurality of second fluid conducting ports is provided, and wherein the outer container is disposed in sealing engagement, or substantially sealing engagement, with the plurality of fluid-conducting conduits such that sealing, or substantial sealing, of fluid communication, within the outer container, between (i) the at least one first fluid conducting port of one of the fluid-conducting conduits and, at least, (ii) the at least one first fluid conducting port of another one of the fluid-conducting conduits, is effected.
 12. The system as claimed in claim 1, further comprising: respective to each one of the fluid-conducting conduits, at least one fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation, such that a plurality of fluid conducting ports is provided; wherein, the at least one fluid conducting port, respective to a one of the fluid-conducting conduits, is spaced apart from the at least one fluid conducting port respective to another one of the fluid-conducting conduits.
 13. The system as claimed in claim 12, wherein the spacing apart is by a minimum distance of at least 15 metres.
 14. The system as claimed in claim 1, further comprising: respective to each one of the fluid-conducting conduits, at least one fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation, such that a plurality of fluid conducting ports is provided; and respective to at least one of the fluid-conducting conduits, a pair of sealing members extending from the fluid-conducting conduit, wherein the at least one fluid conducting, of the fluid-conducting conduit to which the pair of sealing members is respective, is disposed between the pair of sealing members; and wherein the pair of sealing members is configured such that, when the apparatus is deployed within the wellbore, the sealing members are disposed, or deployable into a disposition, to prevent, or substantially prevent, fluid communication, through a wellbore annulus, between: (i) the at least one fluid conducting port, disposed between the pair of sealing members, and (ii) a fluid conducting port of another one of the fluid-conducting conduits.
 15. The system as claimed in claim 14, wherein the pair of sealing members is configured such that, when the apparatus is deployed within the wellbore, the sealing members are disposed in, or deployable into a disposition of, sealing, or substantially sealing, engagement with a surface that, in co-operation with at least the apparatus, defines a wellbore annulus.
 16. The system as claimed in claim 15, wherein the surface is a portion of the subterranean formation.
 17. The system as claimed in claim 15, wherein the surface is that of a portion of a casing that is lining the wellbore, or a portion of a liner that is hanging from the casing.
 18. The system as claimed in claim 14, wherein each one of the sealing member includes a packer.
 19. The system as claimed in claim 14, wherein, the pair of sealing members is configured such that, when the apparatus is deployed within the wellbore, and injection fluid is being injected from the at least one apparatus port into a subterranean zone, the pair of sealing members effects isolation, or substantial isolation, of the injected injection fluid from the remainder of the subterranean formation.
 20. The system as claimed in claim 1, further comprising: respective to each one of the fluid-conducting conduits, at least one fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation, such that a plurality of fluid conducting ports is provided; and respective to at least one of the fluid-conducting conduits, a pair of sealing members extending from the fluid-conducting conduit, wherein the at least one fluid conducting port, of the fluid-conducting conduit to which the pair of sealing members is respective, is disposed between the pair of sealing members; wherein, the pair of sealing members is configured such that, when the apparatus is deployed within the wellbore, and the pair of sealing members are disposed in sealing engagement with the formation, and injection fluid is being injected, from at least one apparatus port of the fluid-conducting conduit to which the pair of sealing members is respective, into a subterranean zone, the pair of sealing members effect isolation, or substantial isolation, of the injected injection fluid from the remainder of the subterranean formation.
 21. The system as claimed in claim 20; wherein each one of the sealing members includes a packer.
 22. The system as claimed in claim 1, further comprising: respective to each one of the fluid-conducting conduits, at least one fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation, such that a plurality of fluid conducting ports is provided; and respective to at least one of the fluid-conducting conduits, a pair of sealing members extending from the fluid-conducting conduit, wherein the at least one fluid conducting port, of the fluid-conducting conduit to which the pair of sealing members is respective, is disposed between the pair of sealing members; wherein the pair of sealing members are disposed in, or deployable into a disposition of, sealing engagement or substantially sealing engagement with a surface that, in co-operation with at least the apparatus, defines a wellbore annulus.
 23. The system as claimed in claim 22, wherein the surface is a portion of the subterranean formation.
 24. The system as claimed in claim 22, wherein the surface is that of a portion of a casing that is lining the wellbore, or a portion of a liner that is hanging from the casing.
 25. The system as claimed in claim 22, wherein each one of the sealing members includes a packer.
 26. The system as claimed in claim 1, further comprising: respective to each one of the fluid-conducting conduits, at least one fluid conducting port for conducting fluid, when fluid is flowing through the conduit fluid passage to which the apparatus port is respective, to a subterranean zone of the subterranean formation, such that a plurality of fluid conducting ports is provided; wherein each one of the fluid-conducting conduits, independently, includes a valve member configured for at least interfering with fluid communication, through the fluid passage, between a fluid source upstream of the valve and the at least one fluid conducting port.
 27. The system as claimed in claim 26, wherein the valve member is configured for disposition between an open condition and a closed condition, wherein, in the open condition, fluid communication, through the fluid passage, is effected between a fluid source upstream of the valve member and the at least one fluid conducting port, and wherein, in the closed condition, sealing, or substantial sealing of fluid communication, through the fluid passage, between a fluid source upstream of the valve member and the at least one fluid conducting port, is effected.
 28. The system as claimed in claim 26, wherein the valve member, of each one of the fluid-conducting conduits, is configured for disposition above the wellhead when the apparatus is disposed within the wellbore.
 29. The system as claimed in claim 26, wherein the valve member, of each one of the fluid-conducting conduits, is configured for disposition above the surface when the apparatus is disposed within the wellbore. 